To obtain hydrocarbons such as oil and gas, boreholes are drilled by rotating a drill bit attached at a drill string end. A large proportion of the current drilling activity involves directional drilling, i.e., drilling deviated and horizontal boreholes, to increase the hydrocarbon production and/or to withdraw additional hydrocarbons from the earth's formations. Modern directional drilling systems generally employ a drill string having a bottomhole assembly (BHA) and a drill bit at end thereof that is rotated by a drill motor (mud motor) and/or the drill string. A steering assembly may be used to steer the BHA in a desired direction.
In many instances, the wellbore path or trajectory is designed to intersect a hydrocarbon reservoir in a manner that is expected to most effectively drain that reservoir. To execute such a path or trajectory, extensive information must be known as to the lithology of a formation and its geophysical characteristics. Some of this information is obtained during seismic prospecting operations. Also, logging operations can be done in a drilled well or offset well using formation evaluation tools to develop additional data regarding the formation of interest. More sophisticated BHA's are equipped with devices for measuring various formation parameters of interest. Such devices typically include sensors for measuring downhole temperature and pressure, azimuth and inclination measuring devices and a resistivity measuring device to determine the presence of hydrocarbons and water. This information, which is obtained during drilling, can be used to navigate toward, away or through a formation of interest (also known as “geosteering”).
One operation for developing geological information useful for directional drilling is vertical seismic profiling (VSP). Vertical seismic profiling or “VSP” is a well known technique to obtain data on the characteristics of lithological formations. In one conventional VSP operation, drilling is paused and the drilling assembly is extracted from the wellbore. Thereafter, one or more seismic sources are positioned near the borehole at the surface and a sonde having one or more seismic detectors is lowered into the borehole on a wireline cable. The sonde is then positioned at a number of depths in the well while the sources are activated and seismic readings are taken. In another conventional arrangement, a seismic detector is provided on the bottomhole assembly. As the bottomhole assembly progresses into the formation, drilling is intermittently halted at selected depths so that the VSP survey can be performed. As can be seen, in both conventional arrangements, drilling activity can be interrupted for an extended period to accommodate the VSP survey. Given that the data obtained by VSP can be valuable in well management during production as well as during drilling, what is needed is a more effective manner of performing VSP.
Cost-effective hydrocarbon recovery also depends, in part, on drilling a wellbore quickly with minimal downtime. Because equipment failure is one frequent source of downtime, conventional BHA's are equipped with a number of sensors that measure various parameters relating to the operating status, health or condition of the components making up the BHA. For example, these sensor can measure: (a) borehole pressure and temperature; (b) drilling parameters, such as WOB, rotational speed of the drill bit and/or the drill string, and the drilling fluid flow rate; and (c) bottomhole assembly condition (parameters), such as mud motor differential pressure, torque, bit bounce and whirl etc. While these sensors can provide useful information regarding the condition of the BHA, conventional systems do not provide information regarding the equipment (e.g., drill string) uphole of the BHA or information regarding the wellbore and adjacent formation uphole of the BHA. In particular, information is not provided from distributed locations along an extended portion of the drill string. Conventionally, information is collected at only a localized point in the BHA, if at all.
This can be a drawback when models are used to assess the condition of the BHA and drill string and effectiveness of the drilling operation. These models can be simulation models for predicting BHA response to changes in drilling parameters or conditions. Information as to the drill string, wellbore, and formation at distributed or spaced-apart locations uphole of the BHA can improve the accuracy of such models. Thus, this information conventionally is estimated (e.g., based on a single measurement or information obtained hours or perhaps days earlier). In other arrangements, this information is simply omitted. The modeling used to assess the condition of the BHA and improve drilling operations would be more effective if this information was available and measured rather than estimated.
Further, conventional control systems and devices for controlling the drilling system utilize displays that convey information relating to drilling activity in numeric and/or alphanumeric format. These conventional techniques of displaying data visually disassociate the data from the component or location to which the data pertains. One drawback with such display formats is that it can be difficult for the driller to form an intuitive understanding of the overall physical condition of the drilling system. For example, it can be difficult for a driller to identify interrelationships between two or more measured physical conditions.
The present invention addresses these and other needs in the prior art.